There was not lot of public data pv magazine USA could find on these projects, however, it was most important to note that a conservative electricity utility – the one that emits the second largest volume of greenhouse gases by an electric utility in the United States – sees energy storage as part of its “growth and low-risk business strategy of developing or acquiring interests in projects covered by long-term contracts.” And it quite jives with this publication’s pontification that energy storage is investment grade.

Southern Power, a subsidiary of Southern Company, has partnered with esVolta to develop four energy storage facilities located, some located in Southern California Edison (SoCal) territory. The four facilities total more than 86 MW / 345 MWh. Southern Power has fully closed on the investment in one of the four projects, with the other three subject to completion.

Other projects recently developed by esVolta in California and beyond, below, might give insight into what is being invested in here.

In the fall, esVolta won four other projects in SoCal territory – the Wildcat Energy Storage project (above image) will feature a 3 MW/12 MWh near Palm Springs, and the three Acorn Energy Storage (Acorn I in below image) projects will total 6.5 MW/26.5 MWh in Thousand Oaks. The Wildcat Energy Storage project is intended to bolster local distribution networks enabling wires upgrades to be deferred. The technical aspects of the projects were outlined in SoCal’s “Energy Division Technical Review and Disposition” (pdf).

In a press release published in January, esVolta President & Founder Randolph Man noted that the contract responsibilities in their projects vary – as in some, the utility customer purchases capacity, while the developer retains the ability to provide additional value-added energy and ancillary services into the local market. Whereas, at their 6.5 MW/26 MWh Don Lee system in Escondido, the utility bought the whole bundle of services.

esVolta’s Stratford Energy Storage project (featured image of article) is an 8.8 MW/40.8 MWh system located in the city of Stratford, Ontario, Canada, and is the largest battery storage facility in Canada. The facility provides voltage control, frequency regulation, and system peak reduction operations.

Partially overshadowed because of other larger projects, esVolta also participated in PG&E’s ground breaking (and now at risk due to a bankruptcy) 567 MW / 2.27 gigawatt-hours (GWh) energy storage solicitation last year. The 75 MW / 300 MWh Hummingbird facility is esVolta’s largest project to date and it is primarily intended to relieve local capacity constraints caused by retiring fossil fuel units.

Electricity grids that incorporate storage for power sourced from renewable resources could cut carbon dioxide emissions substantially more than systems that simply increase renewably sourced power, a new study has found.

The study, published today in the journal Nature Communications, found that storage could help make more efficient use of power generated by sources such as wind and solar and could help power grids move away from relying on fossil fuels for energy.

“With solar and wind, you can’t flip them on immediately when you need more power,” said Ramteen Sioshansi, a co-author of the study and professor of integrated systems engineering at The Ohio State University. “So the more renewable energy you put into your system, the greater your need to be able to forecast when those energy sources might be available — unless you can find an affordable, reliable way to store that energy.”

The study was among the first of its kind to evaluate the role energy storage might play in making renewable resources more reliable on a grid-wide basis.

The researchers looked at the power grids in California and Texas, then modeled the ways in which energy storage might make better use of energy from renewable sources — and the ways in which storing energy from renewable sources might affect the amount of carbon dioxide the energy grid pumps into the atmosphere.

They found that in California, without energy storage, one-third of the renewable energy could be lost or never collected in the first place. And adding energy storage technologies — batteries and the like — could reduce carbon dioxide emissions by 90 percent.

Under the study’s models, holding energy from renewable sources also made the system much more efficient: Just 9 percent of renewable energy was lost.

In Texas, a state that generates a smaller percentage of its energy from renewable sources than California, the researchers found that adding energy storage technologies to the grid could reduce carbon dioxide emissions by about 57 percent. Under that model, just 0.3 percent of the renewable energy in Texas’s system would be lost.

“Renewables are good, but they have their own challenges,” said Maryam Arbabzadeh, a research fellow at the University of Michigan and lead author of the study. “The sun is not always shining; the wind is not always blowing. Sometimes the amount of solar and wind power doesn’t match the demand. As we think about how to de-carbonize our systems, a combination of all of these technologies could be beneficial for the system to minimize carbon dioxide emissions.”

Tesla has launched a new utility-scale energy storage product called Megapack modeled after the giant battery system it deployed in South Australia as the company seeks to provide an alternative to natural gas “peaker” power plants.

Megapack is the third and largest energy storage system offered by Tesla. The company also sells the residential Powerwall and the commercial Powerpack systems.

Megapack, which Tesla announced Monday in a blog post, is the latest effort by the company to retool and grow its energy storage business, which is a smaller revenue driver than sales of its electric vehicles. Of the $6.4 billion in total revenue posted in the second quarter, just $368 million was from Tesla’s solar and energy storage product business.

Tesla did deploy a record 415 megawatt-hours of energy storage products in the second quarter, an 81% increase from the previous quarter, according to Tesla’s second-quarter earnings report that was released July 24. Powerwalls are now installed at more than 50,000 sites.

The Megapack offering could provide an even bigger boost if Tesla can convince utilities to opt for it instead of the more common natural gas peaker plants used today. And it seems it already has.

Tesla’s Megapack will provide 182.5 MW of the upcoming 567 MW Moss Landing energy storage project in California with PG&E.

The so-called Megapack was specifically designed and engineered to be an easy-to-install utility-scale system. Each system comes fully assembled — that includes battery modules, bi-directional inverters, a thermal management system, an AC main breaker and controls — with up to 3 megawatt-hours of energy storage and 1.5 MW of inverter capacity.

The system includes software, developed by Tesla, to monitor, control and monetize the installations, the company said in a blog post announcing Megapack.

Tesla Energy deployed a new record amount of energy storage during the last quarter, but its solar business is still declining.

With the release of Tesla’s Q2 2019 financial results, the company announced 81% growth in energy storage deployment for a new record of 415 MWh during the last three months:

“Powerwall and Powerpack deployment grew by 81% in the second quarter to a record 415 MWh. Powerwalls are now installed at more than 50,000 sites. Additional cell supply combined with our new module line designed by Tesla Grohmann enabled a step change in energy storage production.”

For the last few years, Tesla’s Powerwall deployment has been fairly limited, which the company attributed to battery cell supply constraints.

Over the last few months, Panasonic increased production capacity at Tesla’s Gigafactory 1 from 23 GWh to a ~28 GWh annual production rate.

This 5 GWh difference enabled Tesla to increase Model 3 production and still have enough to increase the production of its stationary energy storage products: Powerwalls and Powerpacks.

As for its solar business, Tesla noted another decline:

“Solar retrofit deployments declined sequentially to 29 MW. We are in the process of improving many aspects of this business to increase deployments.”

Tesla has indeed been revamping its solar business lately.

Tesla Solar Revamp
SolarCity has long been the biggest residential solar company in the country, but it also consistently delivered losses throughout its existence.

It pioneered new models to sell solar power systems with no upfront cost by leasing them to homeowners and selling them the electricity it generates, like a regular electric utility.

The model created impressive growth, but it required them to pay for the costly systems upfront on most installations, which weighed heavy on their financials.

When Tesla acquired SolarCity back in 2016, it gradually moved away from that model in order to make the company more sustainable, but it also destroyed its growth.

Now as part of Tesla Energy, its solar business saw its revenue plunge every quarter and gross profits are down as well.

Last month, Tesla slipped to third place for residential solar installations in the US.

CEO Elon Musk has been guiding a reversal of that trend in 2019 with a ramp-up of the Tesla solar roof tiles and solar panels for the roof retrofits.

Earlier this year, Tesla announced a plan to revive its solar business by undercutting the competition with <$2 per watt systems.

Yesterday, we reported on Tesla starting to deploy solar power systems in 24 hours after ordering online.

A major disruption to the global economy is coming in the form of a seismic shift in energy markets. Largely driven by energy storage, this disruption will create exciting opportunities for the renewable energy market and will, in our view, drastically change the time of day electricity price curve (that is, the ‘duck curve’).

The increased availability and adoption of battery storage will enable solar energy generators to match for the first time the supply of electricity to the time of customer use, which has historically been the major impediment to the growth of direct renewable electricity supply. In time, the ability for renewable energy to supply generation as needed throughout a 24 hour window has the potential to widen and eventually flatten the electricity price curve, such that the head and the tail will almost be completely “cut off” the duck.

The Duck Curve
For those wondering if this is an article about the energy market or a recipe for Peking duck, the ‘duck curve’ refers to the graph of the price of electricity across a day, which peaks in the morning (the tail), slumps in the middle of the day (the belly) and peaks again in the early evening (the head). With a bit of creative licence this curve resembles a duck – see Figure 1 below.

The “Fat Duck” – How Solar Generation has Impacted Energy Market Supply to Date
Over the last decade the price of electricity has been falling significantly from mid-morning, bottoming out around 12 noon and then increasing in the early evening. Graphically, this has resulted in the day price energy curve resembling a “fatter” duck, as the duck’s belly has been hanging lower and lower – see Figure 2 below.

So what is causing this fattening? Mid-day reductions in electricity demand are being driven by the increase in behind the meter solar generation, particularly residential rooftop solar. Macro-economic trends are also reducing commercial and industrial electricity demand as the economy shifts more and more towards a service-based economy from a manufacturing and industrial base.

Meanwhile our lives have become more and more electrified, including through internet usage (data being directly correlated with electricity), the use of electricity for heating and cooling our homes, and the electrification of transportation through the increased adoption of electric vehicles. All of this results in a mismatch between when we need electricity and when it is created.

A low-cost, high-performance battery chemistry developed by University of Colorado Boulder researchers could one day lead to scalable grid-level storage for wind and solar energy that could help electrical utilities reduce their dependency on fossil fuels.

The new innovation, described today in the journal Joule, outlines two aqueous flow batteries, also known as redox flow batteries, which use chromium and organic binding agents to achieve exceptional voltage and high efficiencies. The components are abundant in nature, offering future promise for cost-effective manufacturing.

“We’re excited to report some of highest performing battery chemistries ever, beyond previous limits,” said Michael Marshak, senior author of the study and an assistant professor in CU Boulder’s Department of Chemistry. “The materials are low-cost, non-toxic and readily available.”

Renewable energy sources provide a growing share of U.S. electrical production, but currently lack a large-scale solution for storing harvested energy and re-deploying it to meet demand during periods when the sun isn’t shining and the wind isn’t blowing.

“There are mismatches between supply and demand on the energy grid during the day,” said Marshak, who is also a fellow in the Renewable and Sustainable Energy Institute (RASEI). “The sun might meet the grid’s needs in the morning, but demand tends to peak in the late afternoon and continue into the evening after the sun has set. Right now, utility companies have to fill that gap by quickly revving up their coal and natural gas production, just like you’d take a car from zero to sixty.”

Although lithium ion can provide power for smaller scale applications, you would need millions of batteries to backup even a small fossil fuel power plant for an hour, Marshak says. But while the lithium ion chemistry is effective, it’s ill-suited to meet the capacity of an entire wind turbine field or solar panel array.

“The basic problem with lithium ion batteries is that they don’t scale very well,” Marshak said. “The more solid material you add, the more resistance you add and then all of the other components need to increase in tandem. So in essence, if you want twice the energy, you need to build twice the batteries and that’s just not cost-effective when you’re talking about this many megawatt hours.”

Flow batteries have been identified as a more promising avenue. Aqueous batteries keep their active ingredients separated in liquid form in large tanks, allowing the system to distribute energy in a managed fashion, similar to the way a gas tank provides steady fuel combustion to a car’s engine when you push the pedal.

The safety of energy storage systems is under scrutiny after firefighters were injured in an Arizona battery plant explosion in April, and it emerged that at least 23 South Korean plants caught fire in a series of incidents dating back to August 2017.

For now, many experts continue to stand behind energy storage’s track record on safety in the context of the broader power market.

When testing energy storage technologies, safety is not viewed as part of a hierarchy of requirements, but is “a simple pass-fail,” said David Kane, technology development manager at the energy company Centrica in the U.K.

“If we cannot be satisfied that the system is safe, then we just can’t pass go,” he said. “That doesn’t just apply to the final product design. It applies to the installation, the service, the decommissioning [and] the various steps in the supply chain.”

Arizona Public Service (APS) still has not revealed the cause of a blast that the Associated Press last month claimed had “sent eight firefighters and a police officer to the hospital.”

However, as previously noted by GTM, the utility has one of the most aggressive energy storage adoption strategies in the U.S., with plans to install roughly a gigawatt of battery capacity by 2025.

Pressures associated with a hasty build-out of battery capacity appear to have been the cause of numerous lithium-ion facility fires in South Korea.

Last month, S&P Global reported that a five-month investigation into the blazes had put the blame on faulty installations and poor operating procedures rather than the batteries themselves.

How the industry responds is critical
Analysts at Wood Mackenzie predict enormous growth for the global storage industry in the years ahead, reaching 600 gigawatts of stationary storage by 2040, up from about 4 gigawatts today.

But the recent safety incidents are problematic for the lithium-ion battery industry, which even this month was being linked to a fire aboard a Virgin Atlantic flight.

Utility companies seeking to reduce CO2 emissions are increasingly relying on battery energy storage systems to meet peak-power demand as they retire their gas-fired plants. “Providing peaking capacity could be a significant U.S. market for energy storage,” according to a June report from the National Renewable Energy Laboratory. Rapidly falling battery costs make the transition attractive.

“In the next year or two, we’ll see an increasing number of locations where batteries are at the break-even point” of grid parity, says Paul Denholm, NREL principal analyst. “There’s still a tremendous market, on the order of tens of gigawatts of capacity that I think are suitable eventually for replacement by batteries.”

Battery energy storage systems (BESS) are often used to store excess solar and wind energy, and both BESS and renewable-energy generation have grown each year. In 2019, the cost of lithium-ion batteries has plunged while growth of BESS facilities has soared.

In March, BloombergNEF reported the benchmark levelized cost of electricity for Li-ion batteries has fallen 35% since the first half of 2018. And in Q1 2019, U.S. energy storage deployments totaled 148.8 MW, 232% greater than in Q1 2018, the Wood Mackenzie U.S. Energy Storage Monitor reported.

Perhaps more significantly, Q1 2019’s total topped Q4 2018 deployments by 6%, auguring a future of rapid growth. Q4 deployments typically are the highest of the year as developers rush to book completions before year’s end. Deployments in 2019 will total 647 MW, Wood Mackenzie estimates, but by 2024, U.S. energy storage deployments are forecast to reach over 4.5 GW annually.

AES Alamitos broke ground June 27 on a 100-MW/400-MWh battery-based storage system for AES Alamitos Energy Center in Long Beach, Calif., as part of a larger modernization and replacement project at the 2,025-MW gas-turbine AES Alamitos Generating Station. AES claims the new battery storage array will be more than twice the size of the largest such facility currently operating in the U.S. The Alamitos power plant was procured specifically to provide peaking power, company officials say, and its permit for 300-MW capacity allows for considerable growth.

Southern California Edison Co. has a 20-year power-purchase agreement with AES for the 100-MW capacity of the Alamitos Energy Storage project, which will be able to operate continuously for four hours, says Gus Flores, principal manager, origination, at SCE. It’s being built at the existing site of old gas plants. Many gas plants were built along the California coast using ocean water for cooling, but that is no longer allowed and they will be retired in the next five years.